When an oil well is first drilled and completed, the fluids (such as crude oil) may be under natural pressure which is sufficient to produce on its own. In other words, the oil rises to the surface without any assistance.
In many oil wells, and particularly those in fields that are established and aging, natural pressure has typically declined to the point where the oil must be artificially lifted to the surface. Subsurface pumps are located in the well below the level of the oil. A string of sucker rods extends from the pump up to the surface to a pump jack device, or beam pump unit. A prime mover, such as a gasoline or diesel engine, or an electric motor, on the surface causes a pivoted walking beam of a pump jack to rock back and forth, one end connected to a string of sucker rods for moving or reciprocating the string up and down inside of the well tubing.
The string of sucker rods operates the subsurface pump. A typical pump has a plunger that is reciprocated inside of a pump barrel by the sucker rods. The barrel has a standing one-way valve adjacent a downhole end, while the plunger also has a one-way valve, called a travelling valve. Alternatively, in some pumps the plunger has a standing one-way valve, while the barrel has a traveling one-way valve. Relative movement alternatively charges the pump chamber, between the standing and travelling valves, with a bolus or increment of liquid and then transfers the bolus of liquid uphole. More specifically, reciprocation charges a compression pump chamber between the valves with fluid and then lifts the fluid up the tubing towards the surface. The one-way valves open and close according to pressure differentials across the valves.
Pumps are generally classified as tubing pumps or insert pumps. A tubing pump includes a pump barrel which is attached to the end joint of the well tubing. The plunger is attached to the end of the rod string and inserted down the well tubing and into the barrel. Tubing pumps are generally used in wells with high fluid volumes. An insert pump has a smaller diameter and is attached to the end of the rod string and run inside of the well tubing to the bottom. The non-reciprocating component is held in place by a hold-down device that seats into a seating nipple installed on the tubing. The hold-down device also provides a fluid seal between the non-reciprocating barrel and the tubing.
Volumetric efficiency of a pump is reduced in wells that have gas. The compression chamber between the standing and traveling one-way valves fails to fill completely with liquid. Instead, the compression chamber contains undissolved gas, air or vacuum, which are collectively referred to herein as “gas”.
The gas may be undissolved from the liquid (“free gas”) or it may be dissolved in the liquid (“solution gas”) until subjected to a drop in pressure in an expanding compression chamber, wherein the gas comes out of solution. Gas takes the place of liquid in the compression chamber, reducing efficiency. The presence of gas in the compression chamber reduces the efficiency of the pump, and lifting costs to produce the liquid to the surface are increased. This condition is known as “gas interference”.
The presence of too much gas in the compression chamber can completely eliminate the ability of the pump to lift fluid. This is because the gas in the compression chamber prevents the contents therein from being compressed enough, to a pressure high enough, to overcome the hydrostatic pressure above on the traveling valve. This condition is known as “gas locked”, and is a type of gas interference.
In common field practice, a common method to break a gas lock in a conventional pump is to adjust the spacing of the pump setting, placing the bottom of the stroke into an interference state during reciprocation, and tag or impact the pump hard on the downstroke. This is done in an effort to jar the valve open so as to break a gas lock. Hitting the pump to open the valves causes damage to pump components and the rod string. Other prior art attempts to solve the gas lock problem have concentrated on the valves and the compression of a gas in the compression chamber.
Operating the pump in a gas locked condition is undesirable because energy is wasted in that the pump is reciprocated but no fluid is lifted. The pump, sucker rod string, surface pumping unit, gear boxes and beam bearings can experience mechanical damage due to the downhole pump plunger hitting the liquid-gas interface in the compression chamber on the downstroke. Loss of liquid lift leads to rapid wear on pump components, as well as stuffing box seals. This is because these components are designed to be lubricated and cooled by the well liquid.
Gas-locking, and implementation of a prior art solution for overcoming same, not only damages the pump and stuffing box, but can reduce the overall productivity of the well. Producing gas without the liquid component removes the gas from the well. The gas is needed to drive the liquid from the formation into the well bore.
Still another problem arises in the Texas Panhandle of the United States, where some oil fields have a minimum gas-to-oil ratio production requirement. In other words, both gas and oil must be produced. Many gas wells are unable to produce gas at their full potential because the downhole pumps are unable to lift the liquid oil, as the pumps are essentially gas locked.
Still another problem arises in stripper wells, which are wells that produce ten barrels or less of liquid each day. Stripper wells are low volume wells. The output from a stripper well is produced into a stock tank on the surface. Separation equipment, which separates the gas from the well, is not used because the production volume is too low to justify the expense of separation equipment. The gas is vented off of the stock tank into the atmosphere, contributing to air pollution and a waste of natural gas.
Still another problem arises in wells with little or no “rat hole”. The rat hole is the distance between the deepest oil, gas and/or water producing zones and the plugged back, or deepest, depth of the well bore. Conventional downhole pumps cannot pump these wells to their full potential due to the low working submergence of the pump in the fluid. The low submergence results in both liquid and gas being sucked into the compression chamber. If insufficient volumes of liquid are drawn in, the pump is gas locked. In low volume wells, the common practice is to shut the pump off for a period of time to allow the liquid to enter the well bore. But, in wells with little or no rat hole, shutting the pump off has no effect because the liquid level is low. Deepening the well bore is typically too expensive. These wells contain oil, but cannot be produced with prior art pumps.
There are, however, many wells which produce fluids having a high gas content. The pumping efficiency of conventional pumps, as hereinabove discussed, is considerably reduced, and pumping action can be completely blocked. While a liquid is substantially incompressible, hydraulically opening the check valves during the reciprocating pump stroke, a gas is compressible. Thus, gas located between the traveling check valve and the standing check valve can merely compress during the down stroke without generating sufficient pressure to open the traveling valve. No liquid is then admitted above the valve to be lifted during the up stroke and the pump is gas locked. This problem is aggravated in large bore pumps, where considerably more internal volume is available for gas accumulation, with concomitant low pressurization during compression.
In the past, it has been suggested to remedy such gas-locking condition by preventing gas from reaching the pump. One way this was accomplished by using an annulus below the pump inlet. However, in order to implement such a remedy, accurate data is required about the generally unknown formation characteristics. Furthermore, the fluid reservoir characteristics of such formations change with time, requiring constant adjustments to the pump installations.
Applicant has found that the annulus method of preventing gas from reaching the pump is neither practical nor effective.
Such failure to completely fill the chamber is attributed to various causes. In a gas lock situation or a gas interference situation, the formation produces gas in addition to liquid. The gas is at the top of the chamber, while the liquid is at the bottom, creating a liquid-to-gas interface. If this interface is relatively high in the chamber, gas interference results. In gas interference, the plunger (on the downstroke) descends in the chamber and hits the liquid-to-gas interface. The change in resistances causes a mechanical shock or jarring. Such a shock damages the pump, the sucker rods and the tubing.
If the liquid-to-gas interface is relatively low in the chamber, gas lock results, wherein insufficient pressure is built up inside of the chamber on the downstroke to open the plunger valve. The plunger is thus not charged with fluid and the pump is unable to lift anything. A gas locked pump, and its associated sucker rods and tubing, may experience damage from the plunger hitting the interface.
In a pump off situation, the annulus surrounding the tubing down at the pump has a low fluid level, and consequently a low fluid head is exerted on the barrel valve. In an ideal pumping situation, when the plunger is on the upstroke, the annulus head pressure forces annulus fluid into the chamber. However, with a pump off condition, the low head pressure is unable to force enough fluid to completely fill the chamber. Consequently, the chamber has gas or air (a vacuum) therein. A pump (and its associated equipment) that is in a pump off condition suffers mechanical shock and jarring as the plunger passes through the liquid-to gas interface. A restricted intake can also cause pump off.
Accordingly, there is still a need for means to effectively deal with gas-locking in downhole reciprocating pumps.
As set forth above, there are a number of problems that are regularly encountered during oil pumping operations. Oil that is pumped from the ground is generally impure, and includes water, gas, and impurities such as sand. The presence of gas in the oil can create during pumping operations a condition that is sometimes referred to as “gas lock.” Gas lock occurs when a quantity of gas becomes trapped between the travelling valve and standing valve balls. In this situation, hydrostatic pressure from above the travelling valve ball holds it in a seated position, while the pressure from the trapped gas will hold the standing valve ball in a seated position. With the balls unable to unseat, pumping comes to a halt with reduction or cessation of liquid production and other related issues including dry stuffing box failures.
One typical response to gas lock is to remove the oil pump and release the trapped gas. This can be time-consuming and, of course, interrupts pumping operations.
Another approach is to adjust the stroke of the plunger to bottom out, or tap bottom, jarring the balls of the travelling and standing valves off of their valve seats to attempt to influence liquid flow when hydrostatic conditions under gas-locking are unfavorable. The adjustment of the pump requires a service visit and the extent of the tap is not always appreciated at surface when the impact actually occurs one or more kilometers downhole. Further it is understood that rather than have service personnel return multiple times in response to repeated gas-locking, a pump might actually be left configured to tap bottom continuously. The usual result is damage to the sucker rods, rod guides, pump plunger and barrel.